Changing set points in a resonant system

ABSTRACT

A method for changing a set point of a system where period of a dominant resonance of the system is determined, a change profile for the set point change is processed; a time period for the set point change based on the period of the dominant resonance in order to minimize excitation of the dominant resonance is also processed; and the set point change is actioned according to the processed change profile and the time period.

BACKGROUND

Embodiments of the present invention relate to changing levels or setpoints in a resonant system, such as a system in a borehole.

In the oilfield/hydrocarbon industry, boreholes/wellbores are drilledinto subterranean hydrocarbon reservoirs so that the hydrocarbons can berecovered. In general, a borehole is drilled through an earth formationinto a hydrocarbon reservoir and the hydrocarbons are produced throughthe wellbore. Typically, earth formations are explored for hydrocarbons,the borehole is drilled and then completed—which may comprise lining theborehole with cement and/or casing—and then the hydrocarbons areproduced from the borehole, which may require pumps to pump thehydrocarbons up the borehole. Wellbore tools may be used in theborehole, normally suspended on a wireline or attached to adrillstring/coiled tubing, to carry out operations in the borehole toprovide for the construction and completion of the wellbore and/or theproduction of the hydrocarbons.

The drilling of a borehole is typically carried out using a steel pipeknown as a drillstring with a drill bit on the lowermost end; the drillbit is normally attached to or is a part of a bottomhole assemblyattached to the lower end of the drillstring. In a drilling procedure,the entire drillstring may be rotated using an over-ground drillingmotor, or the drill bit may be rotated independently of the drillstringusing a fluid powered/electric motor or motors mounted in thedrillstring just above the drill bit. As drilling progresses, a flow ofdrilling fluid is used to carry the debris created by the drillingprocess out of the wellbore. During the drilling procedure, the drillingfluid is pumped through an inlet line down the drillstring, passesthrough holes in the drill bit, and returns to the surface via anannular space between the outer diameter of the drillstring and theborehole (the annular space is generally referred to as the annulus).

In some drilling systems, as discussed in more detail below, thepressure in the borehole being drilled is controlled in order tooptimize the drilling procedure and/or minimize adverse effectsaffecting the drilling procedure. The drilling system comprises a largedynamic system, a long tube of drill pipe or coiled tubing that issuspended and/or moved within a borehole and a borehole that is full ofa fluid that may be flowing through the wellbore at the same time thedrill pipe or coiled tubing is in motion. As would be expected, thedrilling systems, being large dynamic systems, have resonant propertiesassociated with them.

FIG. 1 illustrates a drilling system for operation at a well-site todrill a borehole through an earth formation. The well-site can belocated onshore or offshore. In this system, a borehole 311 is formed insubsurface formations by rotary drilling in a manner that is well known.The invention can also use be used in directional drilling systems,pilot hole drilling systems, casing drilling systems and/or the like.

A drillstring 312 is suspended within the borehole 311 and has abottomhole assembly 300, which includes a drill bit 305 at its lowerend. The surface system includes a platform and derrick assembly 310positioned over the borehole 311, the assembly 310 including a rotarytable 316, kelly 317, hook 318 and rotary swivel 319. The drillstring312 can be rotated by the rotary table 316, energized by means notshown, which engages the kelly 317 at the upper end of the drillstring.The drillstring 312 is suspended from a hook 318, attached to atraveling block (also not shown), through the kelly 317 and the rotaryswivel 319 which permits rotation of the drillstring relative to thehook. As shown in FIG. 1, a top drive system could alternatively be usedto rotate the drillstring 312 in the borehole and, thus rotate the drillbit 305 against a face of the earth formation at the bottom of theborehole.

The surface system further includes drilling fluid or mud 326 stored ina pit 327 formed at the well site. A pump 329 delivers the drillingfluid 326 to the interior of the drillstring 312 via a port in theswivel 319, causing the drilling fluid to flow downwardly through thedrillstring 312 as indicated by the directional arrow 308. The drillingfluid exits the drillstring 312 via ports in the drill bit 305, and thencirculates upwardly through the annulus region between the outside ofthe drillstring and the wall of the borehole, as indicated by thedirectional arrows 309. In this well-known manner, the drilling fluidlubricates the drill bit 305 and carries formation cuttings up to thesurface as it is returned to the pit 327 for recirculation.

The bottomhole assembly 300 of the illustrated system may include alogging-while-drilling (LWD) module 320, a measuring-while-drilling(MWD) module 330, a rotary-steerable system and motor, and drill bit305.

The LWD module 320 may be housed in a special type of drill collar, asis known in the art, and can contain one or a plurality of known typesof logging tools. It will also be understood that more than one LWDand/or MWD module can be employed, e.g. as represented at 320A. The LWDmodule may include capabilities for measuring, processing, and storinginformation, as well as for communicating with the surface equipment. Inone embodiment, the LWD module may include a fluid sampling device.

The MWD module 330 may also be housed in a special type of drill collar,as is known in the art, and can contain one or more devices formeasuring characteristics of the drillstring and drill bit. The MWD toolmay further include an apparatus (not shown) for generating electricalpower to the downhole system. This may typically include a mud turbinegenerator powered by the flow of the drilling fluid, it being understoodthat other power and/or battery systems may be employed. The MWD modulemay include one or more of the following types of measuring devices: aweight-on-bit measuring device, a torque measuring device, a vibrationmeasuring device, a shock measuring device, a stick slip measuringdevice, a direction measuring device, a rotation speed measuring device,and an inclination measuring device.

Drilling an oil and/or gas well using the drilling system depicted inthe figure may involve drilling a borehole of considerable length;boreholes are often up to several kilometers vertically and/orhorizontally in length. As depicted, the drillstring comprises a drillbit at its lower end and lengths of drill pipe that are screwed/coupledtogether. A drive mechanism at the surface rotates the drill bit againsta face of the earth formation to drill the borehole through the earthformation. The drilling mechanism may be a top drive, a rotary table orthe like. In some drilling processes, such as directional drilling orthe like, a downhole motor that may be powered by the drilling fluidcirculating in the borehole or the like, may be used to drive the drillbit.

The drillstring undergoes complicated dynamic behaviour in the boreholeduring the drilling procedure, which complicated behaviour may includeaxial, lateral and torsional vibrations as well as frictional andvibrational interactions with the borehole. Simultaneous measurements ofdrilling rotation at the surface and at the bit have revealed that whilethe top of the drill string rotates with a constant angular velocity,the drill bit may rotate with varying angular velocities. In extremecases, known as stick-slip, the drill bit or another portion of thedrillstring may stop rotating in the borehole, as a result, the drillstring continues to be twisted/rotated until the bit rotates again,after which it accelerates to an angular velocity that is much higherthan the angular velocity of the top of the drillstring.

Stick-slip is a recognized problem in the drilling industry and mayresult in a reduced rate of penetration through the earth formation, bitwear, tool failures and the like. The sticking of the drill bit in theborehole may reduce drilling rates, result in torsional damage to thedrillstring and the fast rotation of the drill bit, when it is unstuck,may cause damage to the drilling system.

Drilling fluid is a broad drilling term that may cover various differenttypes of drilling fluids. The term “drilling fluid” may be used todescribe any fluid or fluid mixture used during drilling and may coversuch things as drilling mud, heavily weighted mixtures of oil or waterwith solid particles, air, nitrogen, misted fluids in air or nitrogen,foamed fluids with air or nitrogen, aerated or nitrified fluids and. Inpractice, the flow of drilling fluid through the drillstring may be usedto cool the drill bit as well as to remove the cuttings from the bottomof the borehole.

In conventional overbalanced drilling, the density of the drilling fluidis selected so that it produces a pressure at the bottom of the borehole(the “bottom hole pressure” or “BHP”), which is high enough tocounter-balance the pressure of fluids in the formation (“the formationpore pressure”). By counter-balancing the pore pressure, the BHP acts toprevent the inflow of fluids from the formations surrounding theborehole into the borehole. However, if the BHP falls below theformation pore pressure, formation fluids, such as gas, oil and/or watermay enter the borehole and produce what is known in drilling as a kick.By contrast, if the BHP is high, the BHP may be higher than the fracturestrength of the formation surrounding the borehole resulting infracturing of the formation.

When the formation is fractured, the drilling fluid may enter theformation and be lost from the drilling process. This loss of drillingfluid from the drilling process may cause a reduction in BHP and as aconsequence cause a kick as the BHP falls below the formation porepressure. Loss of fluid to the formations as a result of fracturing isknown as fluid loss or lost circulation and may be expensive, as aresult of lost drilling fluid, and increase the time to drill theborehole. Kicks are also dangerous and the liquid and/or gas surgeassociated with the influx into the borehole requires handling atsurface.

In order to overcome the problems of kicks and/or fracturing of theformation during drilling, a process known as managed pressure drilling(“MPD”) has been developed. In managed pressure drilling varioustechniques are used to control/manage the BHP during the drillingprocess. In MPD, the flow of drilling fluid into and out of the boreholeis controlled. This means that pumps that pump the fluid into theborehole and chokes that control the flow of fluid out of the boreholeare controlled to control the BHP. Additionally, gas may be injectedinto the drilling fluid to reduce the drilling fluid density and thusreduce the BHP produced by the column of the drilling fluid in thedrilling annulus. In general, until recently, MPD techniques have beenfairly crude relying on manual control of the pumps and choke.

As can be seen from the foregoing, a drilling system for drilling aborehole through an earth formation is a complex system in which,typically, a drillstring with a bottomhole assembly at its lower end issuspended in a borehole and a drill bit, which is a part of theborehole, is rotated against the earth formation to extend the borehole.The drillstring may be rotated in the borehole to produce a rotation ofthe drill bit. Another option is for a downhole motor to be used torotate the drill bit. In some systems, the drillstring comprises standsof metal pipe that are added to the drillstring as the drill bit extendsthe borehole. In other systems, the drillstring comprises a coiled tubethat is extended into the borehole as the drill bit extends theborehole. In the hydrocarbon industry, once the borehole has beendrilled, pipe, often referred to as casing or a casing string, may beused to line the wellbore. Additionally, in the hydrocarbon industry,wellbore procedures may be carried out using a wireline on whichtools/sensors are attached and the wireline is extended from a surfacelocation down into the borehole so that the tools/sensors can be usedalong the wellbore.

As described above, there are many parameters that may be controlled tocontrol the behaviour of the drilling system. For example, theseparameters include the speed of rotation of the drill bit, the weightapplied to the drill bit, the orientation of the drill bit, theproperties of the drilling fluid pumped around the wellbore, thepressure/rate of pumping of the drilling fluid and/or the like. At thesame time there are also many parameters associated with the drillingfluid they may be varied, such as the pump rate of the drilling fluid,an amount of choke applied to the drilling fluid, a density to thedrilling fluid and/or the like. Additionally, wireline systems mayextend into a borehole and tools, sensors and/or the like may beoperated in the borehole while suspended on the wireline. Operationalparameters can then be associated with the operation of such wirelinetools and systems. Furthermore, pumps, such as electric submersiblepumps (“ESPs”) may be used in the borehole to pump drilling fluid intothe borehole, to pump production fluids out of the borehole and/or thelike. Changes to any of these parameters in a wellbore system may bemade singly or in combination to control thedrilling/wireline/wellbore/pumping process(es). Control of theparameters may be performed by a person, such as the driller, aprocessor and/or a person in combination with a processor.

The systems described above comprise dynamic system in which longlengths of pipe/wireline/tubing are extended from a surface locationdown a borehole and the pipe/wireline/tubing may be moved therein and/orfluids may be moved through the pipe/tubing and/or the borehole.Increasingly, parameters associated with a wellbore procedure, such asdrilling/wireline procedures, pumping procedures and/or the like aresensed and used to provide feedback/input into the ongoingdrilling/wireline/pumping procedure. In some procedures, closed loopautomation provides for automatically carrying out a wellbore procedureusing measurements of the state of the system being used and/ormeasurements of the effect being produced by operation of the system.Moreover, in the dynamic wellbore systems described above, any motors,pumps and/or other types of machinery that are activated/operated in theborehole, such as mud motors, electric submersible pumps and/or the likewill undergo a change in state during their operation and will interactwith the drillstring, tubing, wireline, borehole, the column of fluid inthe borehole and/or the like, when a change of state occurs.

In systems in which a state of the wellbore system and or the effect ofthe wellbore system are sensed during a procedure and/or in autonomousand/or semi-autonomous wellbore systems, a state of the wellbore systemcan be changed based upon sensed/measured properties of the wellbore,the wellbore system, an effect/output of the wellbore system and/or thelike. A change of state of the wellbore system may comprise a change inpumping rate of drilling fluid, an increase in rotation speed of thedrillstring/coiled tubing in the borehole, an increase in motor speed ofa downhole motor, a change in operation parameters of a wellbore tool,raising a drill bit/wellbore tool from a bottom of the borehole or fromcontacting an earth formation, increasing weight-on-bit and/or the like.

Conventionally, a change in state of the wellbore system is directed tobe made as-soon-as-possible when needed based upon measured/sensed datain order to adapt the wellbore system to changes as the wellboreprocedure progresses. Previously, it has been recognized that wellboresystems, because of their configuration, may be associated with resonantfrequencies and, in changing a state of the wellbore system, thesefrequencies may be avoided or filtered from the change of state process.

As discussed above, wellbore systems, like many large dynamic systems,exhibit resonant behaviour. Merely by way of example, in theoilfield/hydrocarbon industry, a drillstring in rotation, changes ofpressure and flow fluctuations in the borehole annulus are examples oflarge dynamic systems. Often the large dynamic systems are required tomove between controlled set-points, for instance changing the rotationspeed of the drillstring, changing the pressure-drop across a choke onthe annulus and/or the like. Making changes in these resonant systemswill often result in development of large amplitude oscillations in thesystem, which may take a long time to die down, thereby interfering withthe wellbore procedure and/or causing damage to equipment in theborehole.

SUMMARY

In general terms, according to one embodiment the present invention,changes in the set-point of a wellbore system (i.e. changing theoperating state of the wellbore system from one level to another, suchas increasing the speed of rotation of a drillstring from one speed toanother) may be made over a time-scale that is controlled by thedominant resonance of the system. In particular, the time-scale may bedetermined according to the period of the dominant resonance. It hasbeen found that by controlling changes in set points in this way, theamplitude of resulting resonant oscillations in the system can beconsiderably reduced.

As a result, embodiments of the present invention may enable anautomated or semi-automated system, where set-point changes are madeover a time-scale controlled by the period of the dominant resonance ofthe system, whereby the automated/semi-automated system can produce acontrolled wellbore system where oscillations of the system arecontrolled/mitigated, wellbore processes are more effectivelycontrolled, and/or desired results are more efficiently achieved.

Accordingly, in a first aspect, one embodiment of the present inventionprovides a method for changing a set point of a system in a borehole by:determining the period of a dominant resonance of the system; processinga change profile for the set point change; determining a time period forthe set point change based on the period of the dominant resonance inorder to minimize excitation of the dominant resonance; and performingthe set point change according to the change profile and the timeperiod. In such an embodiment, resonance data for the system istransformed into control parameters that are used to control theoperation of the system

Further aspects of the present invention provide: a computer programcomprising code which, when run on a computer, causes the computer toperform the method of the first aspect; a computer readable mediumstoring a computer program comprising code which, when run on acomputer, causes the computer to perform the method of the first aspect;and a computer-based system programmed to perform the method of thefirst aspect.

For example, a control system can be provided for changing a set pointof a borehole system, where the control system comprises a processor(s)configured to determine the period of a dominant resonance of thesystem; process a change profile for the set point change from thesensed properties; and determine a time period for the set point changebased on the period of the dominant resonance in order to minimizeexcitation of the dominant resonance; and a controller configured tocontrol the system to perform the set point change according to thechange profile and the time period.

The system thus corresponds to the method of the first aspect. Theprocessor may comprise a downhole processor, a surface processor or acombination of a downhole and a surface processor. The system may be anautomated system. The system may further comprise one or more sensors tosense properties of the system and/or the borehole, the determination ofthe period of the dominant resonance of the system and/or the processingof the change profile being based on the sensed properties.

A further aspect of some embodiments of the present invention provides arig (such as a drilling, exploration or production rig) or a tool (suchas a wireline tool or an electro-submersible pump) that comprises thesystem of the previous aspect.

Optional features of the invention will now be set out. These areapplicable singly or in any combination with any aspect of theinvention.

The borehole system may be a drillstring. In this case, the dominantresonance can be for rotation of the drillstring., and the set point maythen be the drillstring rotation speed. More particularly, there aremany large-scale dynamic systems which during their operations are movedfrom one setting to another. For instance, during the drilling of aborehole, the drillstring rotation speed is regularly changed as theearth formation changes and/or other conditions change.

At the start of a drilling process, in a rotary drilling system using atop drive system, a rotation speed of the top of the drillstring ischanged from zero to some non-zero value (normally a constant value).Large-scale dynamic systems often have one or more resonances atfrequencies that are comparable to or longer than the time-scale takenor necessary for a change from one setting to another setting. Merely byway of example, a drillstring of length 750 meters may have a resonancewith a period of roughly 1 second, and a 7500 meter length drillstringmay have a resonance with a period of about 10 seconds. The dominantresonance for rotation for a drillstring driven at constant rotationspeed typically has boundary conditions close to constant speed at thesurface and free at the distal end, for which the resonant period for aconstant cross-section drillstring would be one quarter wavelength.Thus, with an average wave-speed in drillpipe of around 3000 m/s, theperiod is four times the length of the pipe in meters divided by 3000.For a real drillstring with larger components at the bottom, the periodis longer.

Typically, changes in rotation speed of drillstrings are made overperiods between one and ten seconds. Similarly, lengths of drillingfluid in the borehole/annulus will have resonant frequencies associatedwith them and these may be comparable or longer than the time periodrequired to change, for example, a flow rate of the drilling fluid inthe borehole from a first rate to a second rate.

When the set point is the weight-on-bit, the dominant resonance can befor rotation of the drillstring and/or for axial wave speed in thedrillstring. More particularly, for changes in the axial load(weight-on-bit) of a drillstring, although in some circumstances it maybe advantageous to avoid exciting the fundamental axial resonance (whichis typically close to a half wave-length resonance with a wave speed ofapproximated 5000 m/s), when drilling with a drill bit that generatessignificant torque, and especially a drag bit, such as apoly-crystalline diamond compact (PDC) bit, the fundamental resonancethat is important is generally that of the rotary system, just as forchanging rotation speed. This is because the linear change in weightwill generate a linear change in torque at the bit, and that change intorque will excite the rotary system.

When the set point is the speed of pump(s) controlling flow of fluidinto of the drillstring, the setting of choke(s) controlling flow offluid out of the borehole, and/or gas injection into the fluid in thedrillstring and/or in the annulus around the drillstring, the dominantresonance can be for compression waves in fluid inside the drillstringand/or in fluid in the annulus. More particularly, for resonancesassociated with the fluid inside the drillstring, the typical wave speedis close to the compressional wave speed in the fluid, which varies fromaround 1600 m/s for fully salt-saturated water, to less than 1000 m/sfor a weighted oil-based fluid. The fundamental resonance may be betweena half-wavelength for a large pressure drop at the bit, and a quarterwavelength for a small pressure drop at the bit, and the fundamentalresonance may then be between twice and four times the drillstringlength divided by the wave speed. For resonances associated with thefluid in the annulus, again the fundamental resonance may be between aquarter and a half wavelength, where a quarter corresponds to an openannulus, and a half is a closed choke. The wave speed for waves in theannulus is typically less than inside the drillstring, because of theeffect of the compliant borehole wall, but may also be substantiallyreduced if gas is present in the annulus.

The borehole system may be a wireline/wireline system. For wirelineresonances, the fundamental resonance may typically be close to ahalf-wavelength resonance, and the period may then be close to twice thelength of the wireline, divided by axial wave speed in the wirelinecable (which varies along the length with the wireline tension). Thus,when the set point is the speed of lowering or raising the wireline, thedominant resonance can be for axial wave speed in the wireline.

The borehole system may be an electro-submersible pump. For anelectro-submersible pump (ESP), there are two resonant periods which maybe important, one much longer than the other. The shorter of the two isthe first rotational resonance of the shaft of the pump, which is afixed-free resonance (fixed rotation at the motor end, free at the otherend), which may be close to a quarter wavelength. Although these arerotational waves of the shaft, the extra mass-loading due to the pumpstages means that the average speed of rotational waves may be muchlower than the wave speed for the shaft alone. The wave speed can bereadily calculated as the square root of the mean rotational moment perunit length, multiplied by the mean rotational compliance per unit. Thelonger period corresponds to fluid waves in the production tubing, andmay be between a quarter and half wavelength resonance, with the wavespeed of the produced fluids, which can be could be anywhere between afew hundred meters per second and 1600 meters per second, depending onthe ratio of gas, oil and water, and the salinity of the water. Thus,when the set point is the ESP pump speed, the dominant resonance can bethe rotational resonance of a shaft of the pump and/or for fluid wavesin production tubing in the borehole.

Each change between settings of the wellbore system has a changeprofile, i.e. how the set-point gradient changes with time. For example,the change profile may be linear with the change in rotation beinglinearly increased between settings or the like. A set of times/timedurations that are proportional to the period of the resonance of thedrilling system/aspect of the drilling system is selected over which tomake a set change. By selecting the set change time durations to beproportional to the period of resonance, excitation of the resonance(excitation of large resonant oscillations in the drilling system) bythe set point change is minimized.

For instance, if the change profile is linear with time (constantgradient), i.e. ramping up the speed of rotation of the drilling systemlinearly from a low speed to a higher speed of rotation, the time overwhich to make the change, may be an integer multiple of the resonanceperiod of the drilling system. If, however, the change profile timederivative follows a half-period of a sine-wave or the like, then thetime period over which to make the change may be an integer-plus-a-halfmultiple of the resonance period of the drilling system. More generally,the time period may be a multiple of the period of the dominantresonance.

The change profile may be symmetric about the mid-time of the change. Insuch an embodiment, the change profile may have frequencies that it doesnot excite. The determination of the time period for the set pointchange can conveniently be performed by taking the Fourier transform ofthe time derivative of the change profile.

The period of the dominant resonance can be directly measured, forexample by analysing an appropriate spectrum or time-series (e.g. in thecase of a drillstring, a spectrum or time-series of drillstring torqueor rotation speed measured either at surface or downhole), or it can becalculated using elastic wave appropriate theory (e.g. elastic wavetheory in the case of a drillstring).

For many systems, such as the drillstring described above, the resonanceperiod varies over time (in this case, because in the course of drillingthe drillstring is extended, and the resonance period increasesapproximately proportionately). Furthermore, for devices that interactwith the fluid column in the borehole, the resonant period for the fluidcolumn in the borehole may vary over time as other operations change theproperties of the fluid column, the length of the borehole and/or thelike.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention will now be described by way of examplewith reference to the accompanying drawings in which:

FIG. 1 illustrates a drilling system for operation at a well-site todrill a borehole through an earth formation;

FIG. 2A is a flow-type illustration of a method for performing a levelchange;

FIG. 2B is a flow-type illustration of the functioning of an automatedwellbore system comprising resonance control;

FIG. 3 shows plots of simulated rotation speed at the top of adrillstring against time;

FIG. 4 shows corresponding plots of simulated rotation speed at thebottom of the drillstring against time;

FIG. 5 shows a simple linear rise change profile;

FIG. 6 shows a change profile having a first linear rate and a secondlinear rate; and

FIG. 7 shows a simulation of surface and bit rotation speeds for a 2400m drillstring being started to reach 120 rpm in 4.6 s.

In the appended figures, similar components and/or features may have thesame reference label. Further, various components of the same type maybe distinguished by following the reference label by a dash and a secondlabel that distinguishes among the similar components. If only the firstreference label is used in the specification, the description isapplicable to any one of the similar components having the same firstreference label irrespective of the second reference label.

DETAILED DESCRIPTION

Reference will now be made in detail to embodiments, examples of whichare illustrated in the accompanying drawings and figures. In thefollowing detailed description, numerous specific details are set forthin order to provide a thorough understanding of the subject matterherein. However, it will be apparent to one of ordinary skill in the artthat the subject matter may be practiced without these specific details.In other instances, well known methods, procedures, components, andsystems have not been described in detail so as not to unnecessarilyobscure features of the embodiments. In the following description, itshould be understood that features of one embodiment may be used incombination with features from another embodiment where the features ofthe different embodiment are not incompatible.

It will also be understood that, although the terms first, second, etc.may be used herein to describe various elements, these elements shouldnot be limited by these terms. These terms are only used to distinguishone element from another. For example, a first object or step could betermed a second object or step, and, similarly, a second object or stepcould be termed a first object or step. The first object or step, andthe second object or step, are both objects or steps, respectively, butthey are not to be considered the same object or step.

The terminology used in the description of the disclosure herein is forthe purpose of describing particular embodiments only and is notintended to be limiting of the subject matter. As used in thisdescription and the appended claims, the singular forms “a”, “an” and“the” are intended to include the plural forms as well, unless thecontext clearly indicates otherwise. It will also be understood that theterm “and/or” as used herein refers to and encompasses any and allpossible combinations of one or more of the associated listed items. Itwill be further understood that the terms “includes,” “including,”“comprises,” and/or “comprising,” when used in this specification,specify the presence of stated features, integers, steps, operations,elements, and/or components, but do not preclude the presence oraddition of one or more other features, integers, steps, operations,elements, components, and/or groups thereof.

As used herein, the term “if” may be construed to mean “when” or “upon”or “in response to determining” or “in response to detecting”, dependingon the context. Similarly, the phrase “if it is determined” or “if [astated condition or event] is detected” may be construed to mean “upondetermining” or “in response to determining” or “upon detecting [thestated condition or event]” or “in response to detecting [the statedcondition or event],” depending on the context.

FIG. 2A is a flow-type illustration of a method for performing a levelchange, i.e. set point change, for a wellbore system, in accordance withan embodiment of the present invention.

In step 10, a level change in the operation of an element of a wellboresystem or an element of the wellbore system is selected. In particular,a wellbore system, such as a drilling system, may be being operatedunder one condition, for example a drillstring of the drilling systemmay be being rotated in a borehole at a first rotation speed, and achange to a different operating condition may be required/desired, i.e.,it may be desired/necessary to change the drilling rotation speed.Similarly, in a wellbore production system, such as an artificial liftsystem it may be desired/necessary to start-up an ESP or change the pumprate of the ESP. Another possibility is that it may be desired to changean operating condition of an element of the wellbore system, e.g. wherethe wellbore system comprises a managed pressure drilling system, it maybe necessary/desirable to change the flow rate of the drilling fluid inthe borehole, change the choke aperture applied to drilling fluidsflowing out of the borehole and/or the like.

In step 20, a dominant resonance of the wellbore system is determined.For example, resonant frequencies for a length of drillstring in aborehole may be determined based upon the operating parameters of thedrillstring. Similarly, resonant frequencies associated with a column ofdrilling fluid flowing around/through a borehole may be determined basedupon parameters of the fluid and/or systems operating in the wellbore inthe flowing fluid. Quite often, the dominant resonance of a wellboresystem may be a combination of the length of the system and theproperties of the borehole and/or the fluids in the borehole.

In other examples, resonance frequencies associated with operation of anESP may be determined from operation characteristics of the ESP andconditions existing in the wellbore. In MPD, the length of the wellbore,the pressure in the wellbore, the drilling parameters and/or the likemay be used to determine resonant frequencies associated with operationof the MPD system. The dominant resonance of the wellbore system or anelement of the wellbore system can be processed to determine a period ofthe dominant resonance of the system. This processing of the resonanceperiod may be performed by calculation, modelling, measurement,comparison with previous operations and/or the like. A database/libraryof resonance occurrences for different wellbore systems may be developedwhere the database/library comprises details of the wellbore system,properties of the resonant effect, operating parameters and/or boreholeparameters at or before the occurrence of the resonant effect and/or thelike. The database/library may serve as a knowledge store to determinedominant resonance of a wellbore systems and properties, such asresonance period, of the dominant resonance of the wellbore system.

The period of the lowest frequency resonance of the dominant resonancefor the wellbore system may be calculated to sufficient accuracytheoretically. Alternatively, by making measurements of the wellboresystem and using methods such as Fourier transforms, Hilbert-Huangtransforms, or cross-correlation, the period of the resonance may bedetermined. If the system is changing over time (for instance thedrillstring being lengthened in the case of the rotating drillstring),then the period can be recalculated or re-measured when the system haschanged. The change in period for the changing wellbore system may beestimated.

In step 30, a change profile for the change in level in operation of thesystem is devised. For example, for a change in speed in rotation of adrillstring in a rotary drilling system, a simple ramp up in speed maybe devised to change the speed of rotation from a first rotation speedto a second rotation speed. In another example, a series of steps may beused to ramp the speed of rotation up to the desired rotation speed. Inanother example, the change profile for the drillstring, for operationof a pump, choke and/or the like may be sinusoidal in nature.

In most cases, simply using a linear ramp from one level to another willprovide an adequate change profile. If for some reason such a profile isnot possible or desirable (for instance if the gradient of the changemust start at zero), then an alternative change profile can be used. Toensure that the change profile has frequencies which it does not excite,the gradient of the change profile is preferably symmetric about themid-time of the change. Thus, if the change profile from level a tolevel b is given by f, where:f(0)=af(T)=band the gradient of f is denoted by f′, then preferably for time t,where T/2<t<T, the gradient f′ is:f′(t)=f′(T−t)

In step 40, a time-period over which the change in level of operationmay be carried out in order to minimize excitation of the resonance isdetermined. This processing of the time-period for the level change maybe performed using Fourier or other transforms and/or by other methods.

Although other methods are possible, one way to calculate the requiredtime over which to make the change is to take the Fourier transform ofthe time derivative of the change profile.

The amplitude of the Fourier transform of a function is proportional tothe amplitude of the Fourier transform of its time derivative, dividedby the frequency. Thus if the Fourier transform of the time derivativeof the change profile has a zero at a particular frequency, so does thetime derivative of the change profile.

If the change profile derivative has the symmetry property describedabove, then it will have a zero for some frequency. Thus, if the changeprofile is a ramp (constant derivative), the Fourier transform of thederivative is zero for frequencies which are integers divided by thechange time. Inverting, if the change time is an integer multiple of theresonance period, changing the set point will not excite the resonance.

If the change profile derivative is a sine wave over π radians (180degrees), then this will have a zero in the Fourier transform atintegers plus a half, divided by the change time.

Thus, if the change time is an integer-plus-a-half times the resonanceperiod, changing the set point will not excite the resonance.

In step 50, the change in level in operation of the system is performedusing the change profile over the determined time period.

With the change profile chosen, and the change time calculationcompleted, the change may be made to the system. There will typically bemany different times over which the change can be made, which will notexcite the resonance frequency. For instance in the case of a ramp(constant change profile time derivative), the change time can be anyinteger multiple of the resonance. However, the time period may bechosen so that it is longer than the shortest time over which the changecan physically be made, either by a human operator or a control system,but no longer than is necessary, i.e. the lowest multiple of theresonance time that can effectively be made by the system. However, alonger time (a greater multiple of the resonance period) may be used toensure that the set change is fully and properly performed within thetime period (there may be probabilities associated with the period for astate change that are accounted for in the period selected for the setchange).

In a managed pressure drilling procedure, the resonance time for theannulus of the well being drilled during managed pressure drilling maybe approximately determined by estimating/measuring an approximateaverage speed of sound, and assuming that the fundamental resonance ofthe drilling system/well/annulus is a half wavelength resonance, so theperiod is twice the length of the drilling system/well/annulus,multiplied by the inverse speed of sound.

The inverse speed of sound may be approximated as the square root of theaverage density of the fluid in the drilling system/well/annulus, timesthe average compliance of the fluid per unit volume (which is theinverse bulk modulus, for a stiff-walled annulus). The average densityof the fluid in the drilling system/well/annulus may be determined bysubtracting the pressure at the surface behind the choke from thebottomhole pressure, optionally making an adjustment for the frictionalpressure drop, and then dividing by the vertical depth differencebetween the position of the two measurements and the acceleration due togravity.

The average compliance of the fluid in the drilling system/well/annulusmay be found by taking the total compliance of the fluid and dividing bythe volume of the annulus. The total compliance may be determined bymeasurement, comparison with other similar systems, modelling,experimentation, theoretical calculation and/or the like. The totalcompliance may be determined using a method described in a co-pendingpatent application entitled “WELLBORE HYDRAULIC COMPLIANCE,” filed as aU.S. Provisional Patent Application No. 61/880,074 on Sep. 19, 2013,which is incorporated by reference herein for all purposes.

By determining the resonance period, as described, for the managedpressure drilling system/process, this period can be used to determine atime period for level changes in the managed pressure drilling systemthat do not produce adverse resonance effects.

As described above, the change can be made by a control system that canautomatically follow the desired change profile, but it can also be madeby a human operator, attempting to keep to the required profile. Sincethe low-amplitude intervals around the zeros in the Fourier spectrum ofthe change profile derivative are generally quite wide, the change doesnot generally have to be made over exactly the right time for thebenefits to be seen.

In this specification, the term wellbore system is used to describe asystem that is operated in a borehole, such as a drilling system, anartificial lift system, a wireline system, a coiled tubing system, adownhole motor system, a casing system and/or the like. For purposes ofdetermining the dominant resonance of the system, processing the changeprofile to produce a level change, determining a time period over whichthe level change should be performed and/or the like, the wellboresystem may be considered to comprise the system itself as well asfeatures of the borehole it is contained in and surrounding structure.For example, where the wellbore system is a drilling system for drillingthe borehole, the frictional features between the drilling system andthe borehole wall can be factors in determining the dominant resonance,the change profile, the time-period and/or the like. Similarly,pressures in the borehole, in the formation surrounding the boreholeand/or the like may be factors in determining the dominant resonance,the change profile, the time-period and/or the like. Density of thedrilling fluid/production fluids may be a factor in determinationdetermining the dominant resonance, the change profile, the time-periodand/or the like.

FIG. 2B illustrates an automated wellbore system comprising resonancecontrol in accordance with an embodiment of the present invention.

In step 105, data are received regarding operation/state of a wellboresystem, borehole/formation/reservoir conditions and/or an outputproduced by the wellbore system. Merely by way of example, the wellboresystem may be a drilling system, a managed pressure drilling system, anartificial lift system, a wireline system for operating a tool in aborehole, a wireline system, a downhole motor system, a reaming system,a casing system, a pumping system, a coiled tubing system and/or thelike.

Input controls to the wellbore system and or sensors coupled with thewellbore system may be used to determine the state of the wellboresystem and/or how the wellbore system is functioning. Similarly, sensorsmay be used to sense an output generated by the operation of thewellbore system, one or more conditions in the borehole, conditionssurrounding the borehole and/or the like. Furthermore, models,look-ahead sensors and/or the like may be used to determine conditionsto be encountered by the wellbore system as the borehole is extended.

Data regarding the wellbore system, the borehole, the formationsurrounding the borehole and/or the like may be communicated to one ormore processors.

In step 110, the processor may process the data to determine how thewellbore system should be operated in view of the communicated data.Merely by way of example, operation of a drilling system may controlledin view of the operating state of the drilling system, the conditions inthe borehole, the conditions surrounding the wellbore and/or the like.The drilling system may be controlled to optimize speed of the drillingprocess, reduce wear of the drilling system, to control direction ofdrilling and/or the like. Furthermore, predictive models may be used,which predict results of changing operation of the drilling system, withthe sensed data to determine how the drilling system should be operatedto achieve a desired operating effect. While a drilling system has beenused as an example, other wellbore systems or combinations of multiplewellbore systems may be controlled in the same manner in an automatedwellbore system.

In step 110, the determination of how the wellbore system should beoperated in view of the communicated data may comprise a determinationof level change in the operation of the wellbore system.

In step 120, a dominant resonance of the wellbore system is processed.As noted above, the properties of the wellbore system, the borehole, theformation surrounding the borehole and/or the like may be used toprocess the dominant resonance. In an automated system, the dominantresonance may be repeatedly determined as the wellbore system isoperated and fed to the processor as part of the data communicated tothe processor in step 105. In such an automated system, the dominantresonance may be a factor in the processing of the level change.

In step 130, a change profile for the level change processed in step 110may be processed. In an automated wellbore system, the change profilemay be designed to produce the determined level change in a manner thatoptimizes the operation of the wellbore system. For example, theprocessor based on the communicated data may determine that a drillingsystem, pump and/or the like should be operated at a faster rate andthat this increase in operating rate should, based upon the communicateddata and/or predictive models or the like should be produced by changingoperation of the wellbore system, speed of the drilling system, pumpand/or the like, by increasing the speed according to a certain changeprofile. The change profile may be selected to avoid inputtingfrequencies that themselves may interact with the resonance propertiesof the wellbore system.

In step 140, a time period over which the level change should beperformed in order to minimize excitation of the dominant resonance isprocessed. As noted above, the time period is determined from the periodof the dominant resonance of the wellbore system. The wellbore systemmay be an automated system where the dominant resonance is repeatedlydetermined, in such systems, the time-period for level changes of thewellbore system may be repeatedly determined and fed to the processor instep 105. The dominant resonance and/or the time period for a levelchange may be used as a constraint that is used in processing how theautomated wellbore system is to be operated to produce a desired/setoperational result. More particularly, knowing the relationship betweendominant resonance and the level-change time-period can provide forautomatically operating the wellbore system to produce a desiredoperational result without producing adverse resonance effects.

In step 150, the change in level in operation of the system using thechange profile over the determined time period is performed. Where thewellbore system is an automated system, the change may be performedautomatically. An output may show the change in operation, the basis forthe change in operation and/or the predicted outcome of the proposedchange in operation of the system. Where the wellbore system is asemi-automated system, the change in level may be suggested to anoperator of the system. An output/interface may show the proposed changein operation, the proposed change in operation and/or the predictedoutcome of the proposed change in operation of the system.

FIGS. 3 and 4 show the theoretical effect on the rotation speed measuredat the top and bottom of a drillstring in a vertical well when therotation speed at surface is changed linearly from zero to 100 rpm inhalf the period of the resonance (solid line), the period of theresonance (dashed line) and one and a half times the period of theresonance (dotted line).

The drillstring in this simulation is not drilling, i.e. it is offbottom. In this example the resonant period is about 3 seconds, so thestart-up times are 1.5, 3 and 4.5 seconds respectively.

FIG. 3 shows the rotation speed at the top-drive (the top of thedrillstring), and FIG. 4 shows the rotation speed at the bit (the bottomof the drillstring), in a level change method. The reduction in theresonant oscillations from matching the change time to the resonance, isclearly shown in FIG. 4 where use of an integer multiple of theresonance of the drillstring, the dominant resonance, provides a stablelevel change rather than the oscillations produced by use of thehalf-integers.

Applications of the present invention include: changing the rotationspeed in long slender structures such as drillstrings; changing thechoke pressure at the top of an annulus; changing the pump speed whenpressurizing an annulus changing the speed of a cable winch (such as forwireline logging); and/or the like.

Merely by way of example, an application of a method for level change ina wellbore system, a drillstring in a vertical borehole, is nowdescribed. The drillstring can be started from rest, rotation of thedrillstring initiated from rest, without significant post-start uprotational oscillations if the rotation speed at surface is takenlinearly to the desired rotation speed over a time equal to an integernumber of periods of the fundamental rotational resonance of thedrillstring.

This start up without resonance effect is shown in FIG. 5. The timeinterval t1 is an integer number of periods of the fundamental resonanceof the system, or a time close to this.

The period of the fundamental resonance can be directly measured, bylooking at the spectrum or time-series of torque or rotation speed,measured either at surface or downhole, or it can be calculated usingelastic wave theory.

In many applications, such as that described above, a change profilewhich is a simple ramp over an integral number of resonant periodsprovides good resonance suppression.

In other applications, particularly those involving friction, betterperformance can be obtained with a change profile, which while dependenton the resonant period, is more complicated than a simple ramp.

An example of this is initiating rotation in a deviated well, wherethere is significant frictional interaction between the drillstring andthe wellbore. In this case, a two stage ramp may be desirable, where therotation speed rises first at one linear rate, and then at a secondlinear rate until the desired rotation speed is reached. The secondlinear rate is the same rate as when no friction is present, and thus isdetermined by the resonant period of the system. This change profile isillustrated in FIG. 6.

The time t2 depends only on the drillstring geometry and composition,and not on the friction. If no friction is present, and the drillstringrotation follows the path shown in FIG. 5, then there is a lag betweenthe drillstring turning at the surface, and the bit starting to turn.The time t2 is twice this lag time.

The time t3 depends on the amount of friction that is present, and itsdistribution in the well. When the drillstring is rotating steadilyoff-bottom at speed R_(max), due to the additional torque required toovercome friction, the top of the drillstring will have rotated throughan angle which exceeds the angle rotated by the bottom of thedrillstring (the bit).

This total angle depends on the torque required to overcome friction,and on the rotational compliance of the drillstring (the more compliantthe drillstring, the greater the angle). Let this total angle be Θ. Theadditional time t3 is proportional to Θ and is:

$\frac{2\Theta}{R_{intersect}}$where R_(intersect) is given by:

$R_{intersect} = {\frac{t\; 2}{t\; 1}R_{\max}}$

Thus, the faster the desired final drillstring rotation speed, theshorter the additional time t3.

The time t1 is as described above when starting up a rotation in avertical well. The other two required quantities, Θ and the lag time,would normally be estimated using calculation calibrated by observation,although they could be measured.

Θ can be calculated by combining the torque distribution along thedrillstring, with an elastic model of the drillstring, ensuring that thetotal torque matches that observed in reality, or it can be calculatedusing an elastic wave theory or similar simulation.

The lag time can be calculated using elastic wave theory or othersimulation, ensuring that in the simulation the fundamental drillstringrotational resonance time matches that observed in reality. Such asimulation is shown in FIG. 7, where a 2400 m drillstring is beingstarted to reach 120 rpm in 4.6 s. The lag time is 0.85 s, and thus t2is 1.7 s.

Slopes and times do not have to be exactly those described, as goodperformance can be obtained with quantities that are close, nor does therise profile have to be exactly linear. Although only a few exampleembodiments have been described in detail above, those skilled in theart will readily appreciate that many modifications are possible in theexample embodiments without materially departing from this invention.Accordingly, all such modifications are intended to be included withinthe scope of this disclosure as defined in the following claims. In theclaims, means-plus-function clauses are intended to cover the structuresdescribed herein as performing the recited function and not onlystructural equivalents, but also equivalent structures. It is theexpress intention of the applicant not to invoke 35 U.S.C. § 112,paragraph 6 for any limitations of any of the claims herein, except forthose in which the claim expressly uses the words ‘means for’ togetherwith an associated function.

Numbered Clauses Relating to the Invention

-   Clause 1. A method for changing a set point of a system in a    borehole according to any of the methods described herein.-   Clause 2. A system for changing a set point of a system in a    borehole according to any of the systems described herein.-   Clause 3. A method for changing a set point of a system in a    borehole, comprising:    -   determining a dominant resonance of the system;    -   processing a change profile for the set point change;    -   determining a time period for the set point change to minimize        excitation of the dominant resonance; and    -   performing the set point change according to the change profile        and the time period.-   Clause 4. The method of clause 3, wherein the time period for a    linear change profile comprises an integer multiple of a period of    the dominant resonant frequency.-   Clause 5. The method of clause 3, wherein the time period for a    change profile comprising a half-period of a sine-wave comprises an    integer plus a half multiple of the resonance period.-   Clause 6. The method of clause 3, wherein the system comprises an    automated system and the time period is used to control operation of    the system.-   Clause 7. A system for changing a set point of a system in a    borehole, comprising:    -   one or more sensors to sense properties of the system and/or the        borehole; and    -   a processor configured to:        -   process a dominant resonance of the system;        -   process a change profile for the set point change; and        -   determine a time period for the set point change to minimize            excitation of the dominant resonance.-   Clause 8. The system of clause 7, further comprising:    -   a controller configured to control the system to perform the set        point change according to the change profile and the time        period.-   Clause 9. The system of clause 7, wherein the processor comprises a    downhole processor, a surface processor or a combination of a    downhole and a surface processor.

The invention claimed is:
 1. A method for changing a set point of asystem in a borehole, comprising: determining the period of a dominantresonance of the system; processing a change profile for the set pointchange; determining a time period for the set point change based on theperiod of the dominant resonance in order to minimize excitation of thedominant resonance; and performing the set point change according to thechange profile and the time period.
 2. The method of claim 1, whereinthe time period comprises a multiple of the period of the dominantresonance.
 3. The method of claim 2, wherein the change profilecomprises a linear change profile, and the time period is an integermultiple of the period of the dominant resonance.
 4. The method of claim2, wherein the time derivative of the change profile has a half-periodof a sine-wave, and the time period is an integer-plus-a-half multipleof the period of the dominant resonance.
 5. The method of claim 1,wherein the change profile is symmetric about the mid-time of thechange.
 6. The method of claim 1, wherein the determination of the timeperiod for the set point change is performed by taking the Fouriertransform of the time derivative of the change profile.
 7. The method ofclaim 1, wherein the borehole system comprises a drillstring.
 8. Themethod of claim 1, wherein the borehole system comprises a wireline. 9.The method of claim 1, wherein the borehole system comprises anelectro-submersible pump.
 10. A control system for changing a set pointof a system in a borehole, comprising: a computer processor configuredto: determine a period of a dominant resonance of the system; process achange profile for a set point change from sensed properties; anddetermine a time period for the set point change based on the period ofthe dominant resonance in order to minimize excitation of the dominantresonance; and a controller configured to control the system to performthe set point change according to the change profile and the timeperiod.
 11. The control system of claim 10, further comprising one ormore sensors to sense properties of the system and/or the borehole, thedetermination of the period of the dominant resonance of the systemand/or the processing of the change profile being based on the sensedproperties.
 12. A rig or a tool having the control system of claim 11.13. The control system of claim 10, wherein the system comprises amanaged pressure drilling system.
 14. The control system of claim 10,wherein the system comprises a drilling system.
 15. An automated systemfor operating one or more systems in a borehole, wherein the automatedsystem comprises the control system of claim 10.